Enhanced oil recovery processes commonly inject water into a subterranean oil reservoir via one or more injection wells to facilitate the recovery of oil from the reservoir via one or more oil production wells. The water can be injected into the reservoir as a waterflood in a secondary oil recovery process. Alternatively, the water can be injected into the reservoir in combination with other components as a miscible or immiscible displacement fluid in a tertiary oil recovery process. Water is also frequently injected into subterranean oil and/or gas reservoirs to maintain reservoir pressure, which facilitates the recovery of oil and/or gas from the reservoir.
Injection water is oftentimes seawater or a produced water, particularly when the injection wells are offshore, because of the low-cost availability of sea water or produced water at offshore locations. Another motivation for using produced water as an injection water at offshore locations is the difficulty in disposing the produced water offshore. In any case, seawater and produced water are generally characterized as brines, having a high ionic content relative to fresh water. For example, the brines are often rich in sodium, chloride, sulfate, magnesium, potassium, and calcium ions, to name a few.
Despite the ready availability of brines as injection water, it has been found that when brines are introduced into a hydrocarbon reservoir certain constituents in the brines, namely sulfate ions, can have significant detrimental operational effects on the injection wells and hydrocarbon production wells and can ultimately diminish the amount or quality of the hydrocarbon product produced from the hydrocarbon production wells. Sulfate ions can form salts in situ when contacted with metal cations such as barium, which are naturally occurring in the reservoir. Barium sulfate salts readily precipitate out of solution under ambient reservoir conditions. The resulting precipitates accumulate as barium sulfate scale in the outlying reservoir and at the well bore of the hydrocarbon production wells. The scale reduces the permeability of the reservoir and reduces the diameter of perforations in well bores, thereby diminishing hydrocarbon recovery from the hydrocarbon production wells. U.S. Pat. No. 4,723,603 to Plummer (the '603 patent), which is incorporated herein by reference, recognizes the debilitating effect of barium sulfate scale build-up in hydrocarbon production well bores and the outlying reservoir and teaches the desirability of treating sulfate-rich brines used as injection water to reduce the sulfate concentration in the brines before injecting them into the reservoir.
It has also been postulated that a significant concentration of sulfate ions in injection water promotes reservoir souring. Reservoir souring is an undesirable phenomenon, whereby reservoirs are initially sweet upon discovery, but turn sour during the course of waterflooding and attendant hydrocarbon production from the reservoir. Souring contaminates the reservoir with hydrogen sulfide gas or other sulfur-containing species and is evidenced by the production of significant quantities of hydrogen sulfide gas along with the desired hydrocarbon fluids from the reservoir via the hydrocarbon production wells. The hydrogen sulfide gas causes a number of undesired consequences at the hydrocarbon production wells, including excessive degradation of the hydrocarbon production well metallurgy and associated production equipment, diminished economic value of the produced hydrocarbon fluids, an environmental hazard to the surroundings, and a health hazard to field personnel.
The hydrogen sulfide is believed to be produced by an anaerobic sulfate reducing bacteria. The sulfate reducing bacteria is often indigenous to the reservoir and is also commonly present in the injection water. Sulfate ions and organic carbon are the primary feed reactants utilized by the sulfate reducing bacteria to produce hydrogen sulfide in situ and as such is termed a bacteria food nutrient herein. The injection water is usually a plentiful source of sulfate ions, while formation water is a plentiful source of organic carbon in the form of naturally-occurring low molecular weight fatty acids. The sulfate reducing bacteria effects reservoir souring by metabolizing the low molecular weight fatty acids in the presence of the sulfate ions, thereby reducing the sulfate to hydrogen sulfide. Stated alternatively, reservoir souring is a reaction carried out by the sulfate reducing bacteria which converts sulfate and organic carbon to hydrogen sulfide and byproducts.
A number of strategies have been employed in the prior art for remediating reservoir souring with limited effectiveness. These prior art strategies have primarily been single pronged attacks against either the sulfate reducing bacteria itself or against a specific food nutrient of the sulfate reducing bacteria. For example, many prior art strategies for remediating reservoir souring have focused on killing the sulfate reducing bacteria in the injection water or within the reservoir. Conventional methods for killing the sulfate reducing bacteria include ultraviolet light, biocides, and chemicals such as acrolein. Other prior art strategies for remediating reservoir souring have focused on limiting the availability of sulfates or organic carbon to the sulfate reducing bacteria.
Killing the sulfate reducing bacteria or restricting reservoir levels of organic carbon have generally been unsuccessful strategies for remediating reservoir souring. In the case of organic carbon, even if the practitioner were to successfully eradicate a targeted source of organic carbon in the reservoir, such as fatty acids, there are usually abundant alternative indigenous sources of organic carbon in the reservoir proximal to the injection wells, such as residual oil, which would alternatively satisfy the needs of the sulfate reducing bacteria proximal to the injection wells.
In the case of the sulfate reducing bacteria, conventional means of eradicating the sulfate reducing bacteria generally kill off some, if not most, of the sulfate reducing bacteria when applied to a reservoir, thereby initially diminishing the sulfate reducing bacteria level in the reservoir. Nevertheless, it is virtually impossible to completely eliminate the sulfate reducing bacteria from the reservoir due to the impracticality of sufficiently contacting the entire sulfate reducing bacteria population in situ. The surviving sulfate reducing bacteria flourish in the post-treatment environment because the sulfate reducing bacteria killed off is a rich food source for the surviving sulfate reducing bacteria. Therefore, the reservoir sulfate reducing bacteria level is rapidly restored after the initial kill and ultimately exceeds pre-treatment reservoir sulfide reducing bacteria levels. As a result, treatments for killing the sulfate reducing bacteria are believed to be a counter-productive means of inhibiting reservoir souring.
The '603 patent shows that specific filtration membranes can effectively reduce the concentration of sulfate ions in injection water, thereby inhibiting barium sulfate scale formation. Of the known filtration membranes used for treating seawater to produce injection water, nanofiltration membranes are often preferred to reverse osmosis membranes, because nanofiltration membranes generally permit a higher passage of sodium chloride than reverse osmosis membranes. Consequently, nanofiltration membranes are advantageously operable at substantially lower pressures than reverse osmosis membranes. Nanofiltration membranes also maintain the ionic strength of the resulting injection water at a relatively high level, which desirably reduces the risk of clay instability and correspondingly reduces the risk of water permeability loss through the porous substrata of the subterranean formation.
Rizk, T. Y. et al., in their paper “The Effect of Desulphated Seawater Injection on Microbial Hydrogen Sulphide Generation and Implication for Corrosion Control”, Corrosion 98, Paper No. 287, 1998, speculate that the membrane filtration process of the '603 patent can also inhibit reservoir souring for the same reason, i.e., by reducing the injection water sulfate concentration. However, it remains to be seen whether membrane filtration can reduce the sulfate concentration in the injection water to a level which sufficiently inhibits production of hydrogen sulfide.
Other species, namely phosphates, termed a bacteria population growth nutrient herein, are known to favor growth of bacteria populations, but are not specifically used by the sulfate reducing bacteria to generate hydrogen sulfide in the manner of the above-recited bacteria food nutrients, i.e., sulfates and organic carbon. Therefore, no practical consideration has been given in the prior art to inhibiting reservoir souring by treating an injection water in a manner which actively removes bacteria population growth nutrients from the injection water before displacing the injection water through an injection well bore into a reservoir.
The present invention recognizes a heretofore unrecognized benefit of inhibiting reservoir souring by removing a bacteria population growth nutrient from an injection water before displacing the injection water through an injection well bore into a reservoir. More particularly, the present invention recognizes the benefit of a single prong process for inhibiting reservoir souring which specifically removes phosphorous, in the form of phosphates or otherwise, from an injection water before placing the injection water in a hydrocarbon reservoir. The present invention also recognizes the benefit of a multi-prong process for inhibiting reservoir souring which removes phosphorous, in the form of phosphates or otherwise, in combination with the removal of sulfate reducing bacteria, sulfates or other components which promote reservoir souring from an injection water before placing the injection water in a hydrocarbon reservoir. Accordingly, it is an object of the present invention to provide a treatment process which removes phosphorous, in the form of phosphates or otherwise, from an injection water, thereby sufficiently reducing the phosphorous concentration in the injection water to a level below a threshold level required to generate significant and/or detrimental quantities of hydrogen sulfide. It is another object of the present invention to provide a treatment process which removes phosphorous, in the form of phosphates or otherwise, in combination with sulfate reducing bacteria, sulfates or other components promoting reservoir souring from an injection water, thereby sufficiently reducing the concentrations in the injection water of multiple components promoting reservoir souring to levels below threshold levels required to generate significant and/or detrimental quantities of hydrogen sulfide.
These objects and others are accomplished in accordance with the invention described hereafter.